Julia Pyper is a Senior Editor at Greentech Media covering clean energy policy, the solar industry, grid edge technologies and electric mobility. She previously reported for E&E Publishing, and has covered clean energy and climate change issues across the U.S. and abroad, including in Haiti, Israel and the Maldives. Julia holds degrees from McGill and Columbia Universities. Find her on Twitter @JMPyper.

PJM Interconnection’s Board of Managers authorized major changes to the system operator’s capacity market last week that are designed to address grid issues PJM experienced last winter as a result of the polar vortex.

“This design also allows for greater opportunities for all resources to participate in this enhanced capacity market,” according to the board letter.

Except if you ask proponents of commercial solar projects, it doesn’t.

Under the new structure, for electricity providers to receive payments from PJM for capacity contributions to the grid, they must have “the capability to provide energy when needed during both summer and winter peak conditions and extreme weather events.”

For a decade, renewables have been valued in PJM’s capacity market based on their ability to meet demand for a few hours during the summer peak.

“Capacity revenues are very significant for utility-scale solar in PJM territory. For some of the large-scale projects we have, it’s actually worth more than the REC [renewable energy credit] values,” said Brent Beerley, executive vice president at Community Energy, a developer of large-scale solar and wind projects. “The PJM proposed rules would effectively erase those revenue streams.”

To participate in PJM’s capacity markets, solar would need to be available at any hour of the year, as well as in emergency situations. That means solar projects would have to be available at night in January in order to earn capacity revenue at any point in the year.

Large projects between 80 and 100 megawatts in PJM territory are now in jeopardy because these revenue streams are going away, said Beerley. The issue hasn’t been taken up by the wider solar community because the industry in PJM territory has predominantly been built behind the meter, he added.

“The industry hasn’t really been built off of those capacity revenues, because we’re just now, for the first time, seeing large-scale utility projects become economical, mostly because of reduced engineering, procurement and construction costs,” said Beerley. “They’ve gotten low enough that you can make the numbers work.”

Now, as utility-scale projects are becoming more financially viable in PJM territory, they’re poised to lose a meaningful revenue stream.

The proposal will also negatively affect wind, which performed well in excess of expected capacity values during the polar vortex. The American Wind Energy Association joined with Community Energy, E.ON Climate & Renewables North America, SunEdison and others in a letter opposing PJM’s proposed changes.

Demand response, which also played a pivotal role in addressing peak demand last winter, will be negatively affected by the proposal too. According to a letter submitted by the Advanced Energy Management Alliance Coalition, PJM’s new requirements effectively amount to an “anticompetitive cap” on demand response.

A step backward?

According to advanced energy groups, PJM’s proposal essentially ensures that capacity needs will be met by conventional generation alone, since coal, nuclear and gas are the only resources that can meet the year-round, day-and-night dispatch capabilities the new capacity performance model calls for.

“I think PJM is using a blunt instrument by making everybody meet this 365-days-a-year test,” said Michael Jacobs, senior energy analyst with the Union of Concerned Scientists, who’s been tracking this issue. Rather than lump all resources together to address what was largely a natural-gas issue, PJM needs to come up with a more sophisticated, engineering-based solution, he said.

“Solar and wind didn’t cause the issue in the polar vortex. So doing this won’t help anyone in a polar vortex situation; it will just put a chill on investment in solar, wind and demand response,” said Nora Mead Brownell, principal at ESPY Energy Solutions and former FERC commissioner.

It’s unclear why PJM is changing the rules so drastically. On the one hand, it could be an overreaction to the events that took place last year. On the other, it could be political pressure from those “who frankly don’t like intermittent resources,” said Mead Brownell, who is advising the renewable energy industry.

Andrew Ott, executive vice president of markets at PJM, said these criticisms are unwarranted and are relying on old information. PJM is asking its capacity resources for a higher standard of performance year-round, but it is compensating them with capacity performance payments that are roughly two times greater than current rates, from roughly $100-$120 per megwatt to $250-$300 per megawatt.

In addition, resources that overperform during peak hours in either summer or winter will receive a payment of $4,000 per megwatt hour, plus the prevailing energy price. Currently, PJM compensates over-performance based on the prevailing energy price alone.

“The point is while, yes, we would require them to perform in the winter during peak conditions, if they in fact happen, the revenue stream they get from the enhanced capacity payment and performance payments would help them to use some of that money to hedge their performance in winter," said Ott. "It’s not a reduction it’s actually more revenue.”

"They would have to do more hedging than they have to do today, but I don’t understand how that’s a step backwards," he added. "It just doesn’t seem to add up.”

PJM will also allow more flexibility for intermittent resources by expanding the applicability of “coupled resource offers,” which would share responsibility for the capacity performance requirements.

In theory, this sounds great, said Beerley. Solar could team up with wind, demand response or storage and continue to play in the capacity market. But in practice, this will be extremely difficult and expensive to implement, he said.

Shortage events can occur at any time of day or any time of the year, and so intermittent resources would still need to couple with dispatchable ones like a natural-gas peaker plant or a battery. The problem there is that gas peaker plants will already be committed to their own requirements, and batteries are still far too expensive to provide large-scale, multi-hour backup service.

The capacity market proposal has been on fast track to get it done before this winter, in light of the harsh criticism PJM received last year when it experienced 40,200 megawatts of forced outages as a result of the polar vortex. PJM’s own analysis shows that if there were the same number of generator outages this winter, coupled with extremely cold temperatures and expected coal retirements, PJM would not be able to meet its peak load requirements.

PJM is expected to file the plan this week with FERC, which will launch a 60-day review process. If approved by FERC, the changes will begin to take effect in delivery years 2016/2017 and be fully implemented by 2020/2021.

Correction: A previous version of this article said that to qualify as a capacity performance product under the new rules, all generators must be able to operate for sixteen hours a day for three consecutive days. That requirement was struck from PJM's final proposal.